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November 12, 2024

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SPP Board of Directors/RSC Briefs: Aug. 5-6, 2024

Board Approves 36% PRM for Winter over Stakeholder Objections

ST. LOUIS — SPP directors and state regulators have approved the grid operator’s first winter planning reserve margin, endorsing a base PRM that is 3 percentage points higher than many of its utilities wanted.

The Board of Directors during its Aug. 6 meeting approved a 36% PRM for the winter season and a 16% margin for the summer season, effective 2026/27 and 2026, respectively. In doing so, the board sided with the Regional State Committee’s recommendation over that of the Market and Operations Policy Committee, which endorsed a 33% winter PRM.

The approval of the tariff change (RR622) capped months of discussions and deliberations by several stakeholder groups, including the Resource Energy and Adequacy Leadership (REAL) Team that is responsible for resource adequacy issues. (See SPP Markets and Operations Policy Committee Briefs: July 16-17, 2024.)

“I’m very disappointed that we did not agree to common ground with implementing the PRM,” SPP CEO Barbara Sugg said after the vote. “There are things I want to focus on that we all agree with. We agree that we have to get more steel in the ground, and we can’t do that fast enough. We agree nobody wants to explain why we have to shed load or why we’ve been turning away load. Nobody wants to tell customers why the rates are going up. It goes without saying nobody wants to find themselves paying for [RA] deficiencies.

“Again, I’m disappointed when we can’t reach consensus. It’s not who we are. But I know we all want the same thing. We want a reliable, affordable system. We have more work to do to achieve that.”

SPP said the action marks the first time a winter PRM requirement has been defined separately from the summer requirement and was necessary to ensure member utilities acquire enough generating capacity for both seasons. The RTO’s load-responsible entities must have access to enough generating capacity to meet their peak consumption by at least a 36% margin during the winter and at least 16% margin during summer.

The grid operator says severe extreme weather has become “increasingly common” in recent years. The February 2021 winter storm forced SPP to shed load for the first time in its then-80 years of operation. During the December 2022 winter storm, the RTO’s staff was forced to curtail almost 6.5% of demand to prevent uncontrolled outages after a higher-than-expected level of coal-fired generator outages and derates.

“Winter is becoming our trouble season,” RSC President John Tuma said.

Minnesota PUC Commissioner John Tuma | © RTO Insider LLC

SPP’s 2023 loss-of-load study, the first to directly analyze seasonal risk beyond summer, found that a 15% PRM would not meet a 1-in-10 loss-of-load expectation in either season.

The grid operator’s Market Monitoring Unit said it saw 36% as a minimum threshold. It preferred a 37% PRM to allow for extra maintenance outages during winter.

Tuma likened SPP’s quest for the appropriate resource adequacy requirements to a fellowship’s travails straight out of fantasy novels.

“It’s a long journey that we’re on here at SPP … We’re at one of those points where you have a difficult lift,” he said. “You see that the trail turns ahead of you, and you don’t know exactly where it goes. This is difficult stuff. We understand that, but it’s unclear what’s coming around the corner, and we still need to go forward.”

“I wish someone would put together a trajectory that was giving us a pathway to growth and future … so that we know how much water to pack,” American Electric Power’s Richard Ross said. “I don’t want to get down that target and find out we’re going another 20 miles and not having enough water. Let’s not go on that trail and not be prepared.”

Ross was one of 12 Members Committee representatives to oppose the 36% PRM in the committee’s advisory vote for the board, with eight in favor and three abstentions. He said MOPC’s 33% recommendation “strikes the proper balance between what is needed to maintain reliability in the system and what is actually achievable, given the situations that we have.”

Richard Ross, AEP | © RTO Insider LLC

“What we really need to do, though, is figure out what we’re going to do for the long term, so we don’t yet again repeat this exact same conversation where SPP is cranking up the reserve margin,” Ross said. “I think you’ve heard from everyone that it takes five to six years to bring a resource online.”

“At 36%, the region as a whole has enough capacity to meet that requirement, but in all likelihood, the reality is a number of LREs [load-responsible entities] would be short in the near term,” said MOPC Chair Alan Myers, with ITC Holdings.

All 64 of SPP’s LREs met the 15% requirement for this summer.

However, Xcel Energy has issued a request for proposals as it faces the need for more than 3 GW of accredited capacity in its Southwestern Public Service (SPS) footprint. Arkansas Electric Cooperative Corp. CEO Buddy Hasten has said the organization will have to spend $2 billion on new dispatchable generating capacity to meet the requirements.

Tuma agreed that staff, the REAL Team and several stakeholder groups recognize the need for “critical, long-vision steps” beyond the current path.

“We’re soberly going into this knowing that there’s a lot more work in front of us. SPP is on an industrial transition, and it’s not going to be cheap,” he said. “We need to take this back to our commissions, take it back to our state leaders. It will cost money, but we need to do it smartly and wisely. If we don’t do it as part of SPP or MISO, it will be more costly. This is where reliability happens.”

Texas Public Utility Commissioner Lori Cobos cast one of two dissenting RSC votes against the 36% requirement, expressing concern over rising rates and supply chain issues that have increased construction costs.

“The challenge that I have on my end is trying to get to a place where I believe my LREs can feasibly work on these reserve margins that are coming in the next several years in a feasible but also affordable manner,” she said.

The board and RSC also approved a fuel assurance policy (RR621) that SPP says will further strengthen RA policies by placing additional emphasis on conventional resources’ performance during the season’s most critical hours and reduce the PRM’s socialization of capacity allocation.

The MC unanimously endorsed the change, with the Natural Resources Defense Council abstaining.

Rate Cap Increased 10.8%

The directors and members both approved the Finance Committee’s recommendation for a 10.8% increase in SPP’s rate cap, from the 46.5 cents/MWh set in 2021 to 51.5 cents/MWh, effective next year.

FC Chair Stuart Solomon said the bump in the rate cap is in line with previous increases that have averaged 11.2% every three years and will serve as a bridge between the current cap and projected expenses through 2028. He said the compound annual growth of inflation has outpaced the billing units and net revenue requirement (NRR) from 2018-2024.

SPP Director Stuart Solomon | © RTO Insider LLC

SPP calculates its rate cap by dividing the budgeted NRR, including a true-up from prior periods, by the estimated amount of transmission service to be provided under the tariff in the coming calendar year.

“The rate cap is a longer-term planning measure that provides predictability for planning purposes,” Solomon said. “SPP has shown the cost-control over time, from 2018 to the present day, as the services increased very significantly over that period.”

More services mean additional staff, but Solomon noted the RTO’s staff ran a “whole lot” of model runs, all of which indicated a need to increase the cap.

The MC endorsed the increase with a 19-4 vote. AEP, Google, Oklahoma Gas & Electric and SPS all voted against the measure. Several members said they will support the rate increases but will focus more closely on the budget, which will be brought before stakeholders and the board in October.

“I am sympathetic [that] FERC’s continuing orders are getting more and more responsibility into the hands of the RTO. More and more compliance,” said Denise Buffington, Evergy’s director of federal regulatory affairs. “I just encourage the organization to continue their focus on their core mission. It’s nice to have staff, but really, how do we get steel in the ground, how do we get generation connected, how do we get transmission planned in an appropriate way? I will be looking at the budget very closely.”

GI Waivers to be Filed

The board approved staff’s proposal to file two waiver requests with FERC following a unanimous vote by the MC that will help SPP clear the backlog in its generator interconnection queue.

The first waiver would allow SPP to delay the 2024 definitive interconnection system impact study (DISIS) cluster’s first phase. The phase would begin after the 2023 DISIS second phase’s restudy is completed and posted in August 2025; without the waiver, the phase would start before the second phase of the 2022 and 2023 clusters and likely lead to unplanned restudies, staff said.

The second waiver would pause the opening of the 2025 DISIS cluster. Together, staff say they will ease conflicts with their effort to clear the GI queue’s backlog and transition to a new planning process. (See “DISIS Waivers Endorsed,” SPP Markets and Operations Policy Committee Briefs: July 16-17, 2024.)

“This really just reflects the reality of the situation that we’re in, in terms of the sheer magnitude and our customers’ generation figures that we’re seeing in the restudies that are resulting from that,” said Natasha Henderson, senior director of grid asset use for SPP.

“I know efforts to clear the queue are challenging … but it’s not fast enough,” Buffington said. “I still have a lot of concerns about the timing. We’re just asking you to be creative about how we can get the process moving more quickly. There’s a lot of concern about alleged queue jumping, but at some point, we’ve got to cut out speculative developers and get a concrete study and concrete development.”

SPP plans to transition to the consolidated planning process (CPP) in late 2026 after a transition period. Opening the 2025 DISIS would mean the cluster’s generation would “significantly” overlap with the CPP’s transition study and first annual assessment.

FERC’s approval of the waivers would enable the timely completion of backlog studies and allow time to further develop CPP. The grid operator has 416 requests in the GI queue totaling about 84 GW in proposed capacity, down from the original backlog of 1,139 requests for 221 GW of capacity.

SPP Responds to Deficiency Letter

CEO Sugg said staff are working to address FERC’s questions about the Markets+ tariff filing and “some of its nuances, particularly transmission usage.”

The commission on July 31 filed a deficiency letter asking the RTO to address 16 issues with its proposed day-ahead market offering in the Western Interconnection. FERC gave SPP 60 days to respond. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)

“We’ve been working on formulating a response,” Sugg said. “We anticipate filing the response to those questions in the deficiency letter within the next 60 days.”

The Markets+ Participant Executive Committee has set aside an hour during its Aug. 13 meeting in Westminster, Colo., to discuss the deficiency letter with SPP legal staff.

OCC’s Hiett Leaves RSC

Oklahoma Corporation Commissioner Todd Hiett was a no-show for the RSC meeting Aug. 5, two days before he would give up his seat on the committee to seek treatment for alcoholism.

OCC staffer Jason Chaplin represented the state in Hiett’s absence.

Hiett, the RSC’s vice president, also stepped down as the OCC’s chair Aug. 7 but remains on the commission. Some lawmakers have asked for a special session to impeach Hiett. His fellow commissioners have called for his resignation and an independent investigation following two instances of public drunkenness and allegations of sexual misconduct. Hiett has refused to resign but offered to step down as chair.

The OCC elected Vice Chair Kim David as its new chair, and she will replace Hiett on the RSC.

The allegations against Hiett were first publicized last month by The Oklahoman, which reported that one incident occurred June 9 in the lobby of the hotel where the Mid-America Regulatory Conference was being held in Minneapolis. Hiett acknowledged to the newspaper that he had had too much to drink but could not remember any of his alleged actions.

In an additional piece of business, the RSC selected an “F Troop” as its Nominating Committee: Kansas’ Andrew French, Louisiana’s Mike Francis and South Dakota’s Kristie Fiegen. They will be responsible for selecting the committee’s 2025 term leadership.

2025 Operating Plan Endorsed

The board’s approval of its consent agenda included SPP’s 2025 operating plan, as recommended by the Finance and Strategic Planning Committees.

The plan is meant to provide a reference point for the highest priorities that will drive “significant” long-term gains for SPP and its members.

The consent agenda also contained recommended in-service date changes for a pair of competitive project certificates of convenience and necessity (CCNs) recently awarded to NextEra Energy Transmission Southwest (NEET SW). Staff urged approval of the transmission developer’s new in-service dates for its 345-kV Wolf Creek-Blackberry project in Missouri and Kansas and the 345-kV Minco-Draper line in Oklahoma, from Jan. 1, 2025, to July 15, 2025, and from July 1, 2024, to Jan. 31, 2025, respectively.

Staff also recommended new language for Evergy Kansas’ 345-kV Wolf-Creek-Waverly line to include re-termination at Wolf Creek, allowing NEET SW’s Wolf Creek-Blackberry project to progress without crossing the two lines.

NEET SW has been awarded SPP’s last three competitive projects. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021 and SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)

The consent agenda additionally included: Emeka Anyanwu’s (the CEO of Lincoln Electric System) nomination to fill a vacant transmission-using member’s seat on the Human Resources Committee; cost increases for a 138-kV Western Farmers project and Omaha Public Power District upgrades; a sponsored upgrade study for terminal equipment at several Western Area Power Administration substations; and the withdrawal of NTCs for Western Farmers substation work and SPS 115-kV terminal upgrades.

Finally, the agenda had two tariff changes that:

    • RR602: add process structure, tracking and improved criteria for evaluating potential transmission reconfigurations.
    • RR619: add application programming interfaces as an acceptable submittal process.
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California Energy Officials Pitch Pathways Plan to State Senators

California energy agency heads appearing before state lawmakers Aug. 6 pitched the proposed CAISO governance changes being developed by the West-Wide Governance Pathways Initiative, saying that expanding the ISO’s electricity market will provide for increased reliability and cost benefits for state residents.

Though the initiative has been in the works since last year, the state Senate Energy, Utilities and Communications Committee discussed the topic for the first time during an oversight hearing on electricity reliability. Representatives from CAISO, the California Energy Commission (CEC) and the California Public Utilities Commission (CPUC) participated.

The agency leaders outlined the purported advantages of giving the Western Energy Markets (WEM) Governing Body increased authority over CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). They also touched on the Pathways Initiative’s evolving plan to establish an independent Western “regional organization” (RO) that eventually would assume more of the ISO’s market functions. (See New Western ‘Regional Organization’ Could be Folsom-based.)

Electricity markets in the West are “very fragmented,” Alice Reynolds, president of CPUC, told the committee. “So, this effort is really thinking about the benefits of a larger market, meaning, think about a market with a footprint that is larger than any one weather event.”

Reynolds said a shared market would allow stakeholders to optimize resources for reliability and tackle different weather events while also maximizing cost savings for ratepayers. However, she noted that proposed changes under the Pathways Initiative would not involve alterations to CAISO’s balancing authority area, a key concern for California labor groups that blocked previous legislative efforts to “regionalize” the ISO and now say they support a bill to enact the Pathways plan. (See California Labor Groups Affirm Support for Pathways Proposal.)

Sen. Henry Stern (D) asked what additional economic benefits California ratepayers could expect from the state’s participation in the EDAM compared with those currently seen in the WEIM, which provided its participants $365 million in estimated benefits during the second quarter of 2024, according to CAISO. (See WEIM Yields $365M in Q2 Benefits with Hot Start to Summer.)

CAISO CEO Elliot Mainzer said EDAM could double those benefits “on just the economic side” but emphasized the impact of an expanded market on reliability.

“The reliability element is becoming increasingly important. I think as you see the reduction in the number of energy emergency alerts, that’s our goal,” Mainzer said. “We want to keep the system calm. We want to have that wide area of visibility. We want to understand not only what’s happening in California, but what’s happening in the broader West, so that on a day-ahead basis, we’ll have the ability to move power to where it’s most needed, given the capabilities of the transmission system.”

‘Really Good Proposal’

On May 31, the initiative’s Launch Committee unanimously endorsed Step 1 of the “stepwise” proposal issued in April. The Launch Committee presented CAISO with the proposal on June 5, which would revise CAISO’s WEIM charter to elevate the oversight position of the market’s Governing Body over WEIM/EDAM matters to “primary” authority, rather than the “joint” authority it currently shares with the ISO’s Board of Governors.

CEC Vice Chair Siva Gunda said the proposal focuses on furthering the independence of CAISO’s governance structure “to have more people feel confident and comfortable to join the EDAM.”

He noted the proposal also clarified the dual filing — or “jump ball” — process that would occur if the CAISO board disagrees with a market rule filing approved by the WEM Governing Body and submits a parallel filing with FERC.

“There will be a dispute resolution if the boards don’t agree,” Gunda said. But “if the dispute resolution did not bring the two boards together, there is a jump ball filing to FERC, meaning both boards can put their proposal to FERC.”

The CAISO board is expected to vote on the first step of the proposal during a joint meeting with the WEM Governing Body later this month.

Gunda told the senators the Pathways Launch Committee expects to issue a proposal on the effort’s next steps in the fall. (The committee is targeting a Nov. 15 release.) Not explicitly described by Gunda but widely understood by industry stakeholders is that the Step 2 proposal will cover the changes to California law needed to migrate some of CAISO’s market functions to the RO, give the RO sole authority over the WEIM/EDAM and allow the ISO to participate in the new entity.

“I just hope you take the next step,” Stern said. “I think you put a really good proposal on the table.”

However, Sen. Kelly Seyarto (R) questioned whether there has been enough outreach to inform the public about the initiative’s implications, saying, “this is the first time I’ve even seen this.”

“I don’t know what our outreach is to the public and when those meetings are, but this is something important for people to understand,” Seyarto said.

“If it’s something that is just kind of part of a box to check off, ‘oh yeah, we did public meetings, we did this, and now we’re doing this,’ you’re going to have a lot of pushback from the public. Because anything that they think might raise their rate right now — they’re hypersensitive to it,” Seyarto added.

Robert Mullin contributed to this article.

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Demand Growth and Extreme Weather: The Grid’s New Normal

Keeping trees near electric wires trimmed back may not save those wires from damage in a hurricane or tropical storm if branches are flying and trees are uprooted outside a utility’s right-of-way, said ERCOT CEO Pablo Vegas. 

A big storm, with wind and rain, “can create an environment where trees can fall from outside of the right-of-way into it and create just as much damage,” Vegas said during an Aug. 7 online briefing on the grid impacts of extreme weather, hosted by the U.S. Energy Association. 

When Tropical Storm Beryl recently roared through Texas, “there was a lot of the vegetation outside of the utilities’ right-of-way that came into play,” Vegas said, “We’re starting to have conversations about ― how do we work more closely with homeowners who can see risky vegetation that could be compromising the electric infrastructure that happens to be outside the right-of-way?” 

Driven by increasingly frequent and disruptive weather intensified by climate change, discussions of grid reliability and resilience ― defined as the ability to bounce back after such events ― have become industry imperatives, regularly included at conferences and online forums like the USEA briefing. 

What’s new, according to Vegas and other speakers at the Aug. 7 event, is the growing power demand from data centers, and the opportunities and challenges it creates, all of which must be factored into plans for extreme weather.  

Rather than seeing data centers as passive load requiring firm, baseload power, Vegas looks at the massive new installations as potential grid assets that could help maintain equitable access to electricity for all customers. 

Backup generation at data centers, critical for ensuring 24/7 power, could be used for emergency demand management, he said. “We could lean on those customers and say, ‘Hey, we need you to disconnect from the grid for a short period of time. We need to you to use your local generation to alleviate the pressure, so that those who don’t have [backup power] will have adequate capacity to serve during this time of scarcity.” 

Andrea Staid, principal technical lead at the Electric Power Research Institute (EPRI), talked about the need to expand ideas about what “extreme weather” might mean as climate change affects all forms of power generation. 

“Extreme from a weather perspective might no longer be extreme from a system stress perspective when you’re thinking about the grid with increasing renewables,” Staid said. “Wind lulls and solar droughts … are extreme from a resource adequacy perspective, but not so much from a pure weather perspective.” 

EPRI researchers look at interregional transmission as one possible solution as renewable “resources become uncorrelated across larger spatial regions,” she said. “It comes down to data … just having a sufficient amount of data to really capture the [impacts] of these distributions when you’re looking at rare occurrences of both wind and solar droughts.” 

But Ravi Seethapathy, executive chair of Biosirus, an industry consultant based in Canada, countered that different approaches and strategies may be needed when a specific area is hit repeatedly with severe storms. “I’m not quite sure whether that interconnection all over the United States will actually help that area,” Seethapathy said.  

Resilience will need to be multilevel, he said, isolating and protecting certain sections of the transmission grid, using non-wires solutions, such as microgrids, for local reliability, topped off with better public awareness and education.  

“We have not been able to condition the public to take certain quick measures to manage [those storms],” Seethapathy said. “We are constantly on a 24/7, 365, by-the-minute kind of time frame … and maybe all these events are telling us, ‘You now need to be a little more resilient, by way of [changing] your daily practices.’ … 

“That’s the approach we’re advocating.” 

Managing Costs

The pace and cost of extreme weather events continue to rise, according to industry veteran David Owens, formerly executive vice president of the Edison Electric Institute. In the past three years, the U.S. has seen 66 major weather events causing more than $1 billion in damages. The total price tag, from 1980 to today, is $2.8 trillion, he said. 

Owens deftly summarized the challenges for utilities, regulators, grid operators and other industry stakeholders: “How do we mitigate the risk? And how do we, at the same time, not expose electric consumers to exorbitant costs? What are some of the technologies that we can employ?” 

Meeting future load growth will be expensive, “regardless of what happens with climate and extreme weather,” Staid said. Integrating extreme weather resilience into long-term planning for load growth could result in “only a small adder on top of a very big cost to make sure you can ride through these extreme heat events, these extreme cold events.” 

“We absolutely need to keep this extreme weather and climate change in mind, but if we plan ahead of time, it shouldn’t drive the cost up significantly,” she said. 

Seethapathy again said a shift in thinking and in relations between utilities and regulators may be needed.  

“We have got a system where the regulator [and] the utility have got a relationship and things are moving very slowly. Why are the costs so high? It’s because we are using the methodologies of 50 years ago,” he said.  

For example, undergrounding of transmission or distribution lines need not mean burying them four feet deep, Seethapathy said. “Cable protection” can be laid at ground level or “just shallow, below ground,” he said. Existing standards “are just out of whack with today’s times.” 

Lessons Learned

Joining Vegas on the USEA panel, CAISO CEO Elliot Mainzer and MISO Senior Vice President Todd Hillman talked about the lessons learned from previously unprecedented weather events like the 2021 winter storm in Texas, commonly called Uri, and the 2020 August heat waves and rolling blackouts in California.  

In the wake of 2020, California tackled resource adequacy ― ensuring it has enough power on reserve to cover emergencies ― with a vengeance. The state has kept existing generation online ― in particular, the Diablo Canyon nuclear power plant ― while adding more than 20,000 MW of new generation to the grid and “a pretty amazing fleet of lithium-ion batteries, now over 9,000 MW, managing that evening peak in tandem with solar,” Mainzer said.  

CAISO also leans on its Energy Imbalance Market, Mainzer said, “taking advantage of transmission connectivity across broad geographies.” EIM is expanding with new lines into New Mexico and Wyoming, and implementation of its voluntary day-ahead market ― expected to come online in 2026 ― will “offer even greater optimization,” he said. 

“The economics are very compelling, but it’s going to be the reliability benefits ― by reducing the need for energy emergency alerts, calming down the system and taking advantage of wide-area dispatch ― that I think ultimately will provide the greatest customer value,” Mainzer said. 

Hillman said MISO is following an “all-of-the-above” strategy, including its Joint Transmission Interconnection Queue with SPP, aimed at providing more interregional transfer capacity. The $1.8 billion package of projects is expected to go to FERC for approval “very soon,” he said.

Like CAISO, MISO also seeks to beef up its generation, with some of the 350 GW of projects ― mostly wind and solar ― in its interconnection queue, Hillman said. However, MISO’s attempts to set an annual cap on interconnection capacity were turned down at FERC in 2023, and the grid operator has delayed opening the queue for new 2024 applications until it sends a revised proposal to the commission. (See MISO: New Interconnection Queue Cycle to Wait on MW Cap Filing.) 

Hillman also spoke about a shift in thinking about risk parameters under way at MISO. With operations covering 15 states, “we’re looking at any and all resources, that they can stay online as long as they possibly can, despite the pressures on the system. But we’re also looking at what the real value of each asset is worth, what’s called accreditation. So, really, what are those values when you get into a risk situation?” 

The dayslong power outages of Uri notwithstanding, ERCOT has yet to focus on developing more interregional transmission lines. Rather, Vegas said, “we’re starting to look at other steps of voltage in our transmission system, stepping up from what we have today across Texas, a 345-kV system. [We are] starting to evaluate, could a 500- or 765-kV system with a strong backbone network built across the state provide added resiliency should we have isolated areas of intense issues that could come from things like weather events? 

“We think that there’s a lot of potential value to that kind of an infrastructure investment that not only supports resiliency but can also support the tremendous load growth that we’re all talking about too.” A new surge of solar and storage on the system also could help ERCOT ride through the traditionally high-risk times when solar power drops off the system during summer sunsets, Vegas said. 

“This may be the last year that we have real significant risk at solar sunset,” he said. “If we continue to see that trajectory by 2025 into 2026, we could see the summer risk period significantly mitigated because batteries are picking up some of the transition solar ramps as we see the wind come on in the evening.” 

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ACP: $500B in Clean Energy Investments Announced in Two Years

The American Clean Power Association reports that U.S. clean energy investments announced over the past two years have reached a half-trillion dollars. 

That money would pay for at least 161 new manufacturing facilities, with the potential for more than 100,000 new manufacturing jobs and more than 300 GW of new emissions-free power generation. 

Most of the spending and much of the resulting infrastructure are in the future, but the commitments are significant enough for ACP to declare it a manufacturing renaissance in “Clean Energy Investing in America,” the report it issued Aug. 7. 

“These historic investments are providing a powerful engine for job creation across the nation,” ACP CEO Jason Grumet said in a news release. “As demand for electricity continues to rise, clean power is answering the call and propelling a new era for American manufacturing.” 

The two-year period in the report overlaps a historic infusion of federal funding intended to encourage exactly what the report quantifies: clean energy development and the creation of a domestic manufacturing base to supply it.  

The Inflation Reduction Act, signed into law by President Biden in August 2022, has provided billions to encourage the changes the ACP report highlights. 

A geographic look at clean-energy-related manufacturing facilities that were announced or came online after August 2022. | American Clean Power

In the latest example, a day after the report was released, the Department of Energy’s Loan Programs Office announced a $1.45 billion conditional loan guarantee for Qcells to set up what is expected to be the largest solar ingot and wafer factory ever built in the United States.  

The LPO said the Georgia facility would be the first vertically integrated U.S. solar factory in more than a decade and would re-establish critical parts of the domestic supply chain for photovoltaics. 

Grumet said that while headline numbers in the ACP report are remarkable, they are only part of the clean energy transition: “Our ability to deploy new capacity with adequate speed and scale requires dramatic efficiency improvements in federal, state and local decision making. ACP is encouraged by recent bipartisan progress to confront barriers to modernizing America’s energy economy.” 

The report’s statistics run through June 30, 2024. At that point, most of the benefits cited in the report were yet to come: 

    • $500 billion in investments had been announced, but only $75 billion had been made. 
    • Construction or expansion of at least 161 manufacturing facilities had been announced, but at least 119 of the projects were in development. 
    • Only 20,000 of the anticipated 100,000 new manufacturing jobs had been created. 
    • Only about 55 GW of the announced 300 GW of new clean energy generating capacity had become operational. 

Breaking down the numbers: 

    • Solar leads the way in new generation, with 33 GW of new capacity built, at a cost of $42 billion. Onshore wind (11.6 GW, $20 billion) and storage (10 GW, $12 billion) are a distant second and third. 
    • New generation projects totaling $363 billion account for the bulk of the announced $500 billion of investment, followed by manufacturing ($61 billion), supply agreements ($47 billion) and other sectors ($28 billion). 

ACP’s report intersperses the project lists and dollar counts with vignettes diving deeper into some of the new manufacturing created in the past two years: 

    • Form Energy built the first factory for its iron-air, 100-hour battery system in Weirton, W.Va., on the site of a demolished steel mill that was the economic and cultural heart of that community for generations. 
    • GE Vernova announced a $50 million expansion and 200 new jobs at its Schenectady, N.Y., facility, where it produces the largest land-based wind turbine in the United States. 
    • Illuminate USA announced, built and opened a massive plant in Pataskala, Ohio, to produce advanced solar panels. Its workforce already exceeds 800 “illuminators,” and the company expects to surpass 1,200 by the end of 2024. 
    • Vestas, which already invested more than $1 billion in Colorado factories that produce wind turbine blades and nacelles, announced a $40 million expansion of the two facilities and plans to hire upward of 1,000 people. 

Grumet said much more is possible — the nation can be a global leader in clean energy: “If we combine innovations in technology and governing, it is possible to achieve an energy system that is reliable, affordable, secure and clean.” 

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Governance is ‘Key Consideration’ for West, Markets+ Backers Say

Governance should be a “key consideration” for the West in the competition between day-ahead electricity markets because the outcome potentially affects $25 billion a year in energy transactions, according to an “issue alert” issued Aug. 7 by 10 entities that helped develop the SPP Markets+ tariff.

The “governance” alert, addressed to the Markets+ States Committee, is intended to be the first of seven such notices published in coming months by the “Markets+ Phase 1 Funding Parties.”

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Co. of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power.

Those entities, along with the Bonneville Power Administration, which did not sign on to the alert, represent some of the strongest supporters of Markets+ in its competition for participants with CAISO’s Extended Day-Ahead Market (EDAM), designed to extend the capabilities of the Western Energy Imbalance Market (WEIM).

In April, BPA staff issued a “leaning” that cited CAISO’s state-run governance as one of the top reasons the agency should choose Markets+ over EDAM. (See BPA Staff Recommends Markets+ over EDAM.)

In their Aug. 7 alert, the Funding Parties noted the “considerable industry dialogue focused on the market seams that will exist between EDAM/EIM and Markets+, as well as the EDAM/EIM governance enhancements being pursued through” the West-Wide Governance Pathways Initiative, a multistate effort launched last year to create the framework for an independent organization to oversee those markets.

“While both topics are important, the Markets+ Phase 1 Funding Parties believe this dialogue is incomplete without also considering the numerous governance and market design differences between Markets+ and EDAM/EIM that are driving continued support for Markets+,” they said.

The parties derived their $25 billion annual impact estimate from the assumption that transitioning to a full day-ahead and real-time market likely will replace much of the region’s bilateral transactions still occurring “while also impacting forward transactions and the utilization of the Western transmission grid.”

“Sound governance is a foundational requirement for a day-ahead organized market to provide the benefits of increased efficiency and enhanced reliability while also ensuring equitable outcomes for all participants and all Western subregions,” they said.

That entails having a “durable, effective and independent governance structure” that fairly represents all market stakeholders, who would “initiate, develop and own outcomes,” they said.

According to the alert, the Markets+ governance framework “fully achieves” those requirements by having:

    • a “geographically diverse” board that is independent of market participants and has authority over “all aspects” of the market;
    • a “transparent and consensus-based market development process” that is led by stakeholders, who have voting rights to determine whether market design proposals advance;
    • a “fully independent and impartial market operator that does not also act as one of the participating balancing authorities with its own interests”; and
    • a stakeholder framework in which “all generators, load and BAAs are participating in the same manner with equivalent rules, rights and responsibilities.”

The alert additionally notes that the Markets+ governance framework already is up and running, having underpinned the decision-making in developing the market’s tariff, which last week received a deficiency notice from FERC. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)

‘Uncertain Outcome’

In contrast, the parties said, the Pathways Initiative “remains in development, with an evolving scope and an uncertain outcome. Changes to the CAISO governance structure require action at the California legislature.” (See No Clear Blueprint for Western ‘RO’ Stakeholder Process and California Labor Groups Affirm Support for Pathways Proposal.)

They expressed additional skepticism that Pathways would create a governance framework “comparable to” Markets+, saying the initiative’s starting point is an EDAM/WEIM tariff designed under CAISO’s existing governance model, and that Pathways has not proposed to replace it with a “stakeholder-driven design.”

The parties also contended that Pathways has not addressed the fact that “EDAM and EIM were built as extensions of a legacy institutional framework with embedded dependencies on, and obligations to, California state agencies” and has not ensured that CAISO, as the operator of the markets, “will balance the interests of all stakeholders and avoid undue influence from California interests.”

They also argued the stakeholder-driven Markets+ process has produced a market design “substantially different” from EDAM in “several key respects,” which will be the subject of future alerts. Design differences can influence the level of participation in a market, “while also encouraging or discouraging generation and transmission investments,” they said.

“For example, a market that inaccurately suppresses peak prices will discourage flexible generation and storage solutions. Similarly, a market that misallocates congestion costs will generally lead to less economically efficient transmission investments,” the parties said, touching on two issues particularly important to entities in the Northwest, the latter sparking especially sharp controversy after a January 2024 cold snap left the region severely short of energy. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.)

The parties concluded by touting the benefit of competition — in this case between markets.

“Experience in the East demonstrates that the ongoing existence of two or more competing organized markets provides the opportunity for participants to continuously evaluate which organized market provides the best value for its customers. This places ongoing competitive pressure on each organized market to continuously evolve to deliver value to all of its participants and all of its subregions, driving immeasurable value for consumers while also reducing risk.”

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Data Centers Bringing ‘Massive’ Loads to Western Grid

Five years ago, load growth from transportation electrification was a major issue for policy makers, according to speakers at a WECC webinar. Now the focus has shifted to data centers. 

“Over the last year or so, the data center growth has become one of the major challenges for this industry,” said Branden Sudduth, WECC’s vice president of reliability planning and performance analysis, who noted the centers can consume as much as 3 GW of energy. 

“That’s just massive loads that we’re not accustomed to seeing come onto the grid,” Sudduth said. 

The discussion came during a WECC webinar Aug. 7 on emerging risks to reliability in the West. 

In its 2023 Western Assessment of Resource Adequacy, WECC projected the region’s demand would increase 16.8% over the next decade, nearly double the 9.6% growth predicted in its 2022 assessment. The 2023 assessment said the biggest driver of the increased demand is the expansion of data centers, especially in the Northwest. 

Data center growth also is expected in other parts of the Western Interconnection. In its integrated resource plan filed in May, NV Energy said more than 3,000 acres of industrial land had been purchased in Northern Nevada last year for data center development. 

In addition to needing large amounts of energy to process data, data centers require significant cooling, which further increases load. 

New Generation Lagging

During the WECC webinar, Sudduth said the data centers can come online as quickly as 18 months, or even sooner if infrastructure is in place. 

“What we know for sure is that generation doesn’t get built that quickly,” said Kris Raper, WECC’s vice president of strategic engagement and external affairs. 

Although an increasing amount of generation is being planned each year, much of that is not materializing, Sudduth said. 

For example, he said, 14 GW of new energy resources were expected to come online in the Western Interconnection in the first half of 2023. But by the end of 2023, only 55% of those resources had been added. 

Projections of new resources for the following two years were even greater: 17 GW in 2024 and 28 GW in 2025, said Sudduth, who noted the figures were near-term forecasts for resources close to or in the construction phase. 

“We’re getting more and more aggressive with the amount of generation that we’re expecting to bring online,” Sudduth said. “But up to this point, we don’t seem to be able to keep up with that aggressive growth.” 

Sudduth attributed the delays to supply chain issues, which are making it difficult to get equipment such as transformers. And increasing costs are “forcing people to rethink when and if they’re going to build certain resources,” he said. 

One way the generation gap is being filled is through resource retirement delays, Sudduth added. 

EV Concerns

Raper, who noted that data centers had taken over from transportation electrification as a hot topic among policymakers, said both sources of load growth remained on WECC’s radar screen. 

“We’re trying to watch all of it,” Raper said. “Because all of the things are going to have an impact on reliability to the grid.” 

Sudduth said one aspect of EV adoption that makes him nervous is long-haul trucking.  

“[Truck drivers] are not going to want to sit around all day and charge their vehicle, and so it’s going to require massive amounts of power to get those long-haul trucks charged quickly,” he said. “What does that do to load forecasts?” 

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SPP’s Sugg Announces Retirement from RTO

SPP CEO Barbara Sugg announced Aug. 8 that she will retire from the RTO on April 1, 2025, after 35 years of service.

Sugg was appointed to the RTO’s top position in 2020, replacing longtime CEO Nick Brown. Under her guidance, SPP has earned designations as one of the best places to work in Arkansas the past three years; expanded its service offerings and territory into the Western Interconnection with RTO West, Markets+ and other services; and garnered consistently high stakeholder satisfaction ratings.

During her tenure, the RTO has navigated historic challenges that included the COVID-19 pandemic and resulting changes to workplace norms; increasing extreme weather that has affected regional electric reliability; and the ongoing growth in demand for electricity and challenges to resource adequacy.

Sugg said in an email to RTO Insider that she has “bittersweet, mixed emotions” about her planned retirement during an “exciting and rewarding time to be part of the electric utility industry.”

“I have no doubt that SPP’s future is as bright as ever,” she said.

Golden Spread Electric Cooperative’s Mike Wise, one of SPP’s more senior and involved members, noted Sugg’s career has virtually matched his. He commended her for bringing out the best in people and encouraging them to grow.

“Barbara’s leadership and vision guided the SPP through some very difficult times,” Wise told RTO Insider, alluding to the COVID-19 pandemic that hit just after she was named CEO. “She had to create a new corporate culture around remote work and still maintain effective RTO operations. Then she was forced to navigate the highly destructive Winter Storm Uri as an RTO which faced circumstances never seen before in the region.

“She exhibited amazing strength of character and never wavered from her strong belief in the exceptionalism of her employees and the committed stakeholders in the SPP. A big three cheers for a good friend and great leader.”

Joe Lang, Omaha Public Power District’s director of generation strategy and origination and vice chair of the stakeholder-led Markets and Operations Policy Committee, wished the best for Sugg and congratulated her on a “fulfilling” career.

“Barbara has been a strong leader as SPP’s CEO through significant challenges in the electric power industry,” he said. “Barbara will be remembered for her leadership that guided SPP through the pandemic, generation interconnection backlog efforts, navigating resource adequacy constraints during extreme weather events, as well as successes expanding into the West.”

“Barbara’s dedication, passion and support of SPP’s mission and people have been evident throughout her tenure,” John Cupparo, chair of the Board of Directors, said in a news release. “Her impact as a CEO will be felt for years to come, and the board joins SPP’s stakeholders in thanking her for the high standard of leadership she’s set.”

The board plans to name a new CEO before Sugg’s departure, and it has engaged search firm Heidrick & Struggles to assess internal and external candidates as her potential replacement.

“I’m not done until I’m done. I still have much work to do,” she said, crediting SPP’s “dedicated” staff and “diverse” stakeholders. “For now, I remain energized, committed and focused on ensuring SPP’s success and partnering closely with my replacement to ensure she or he is prepared to take the reins.”

Sugg joined SPP in 1997 after eight years with Louisiana Energy and Power Authority. Because LEPA, which comprises 20 municipal power systems, was an SPP member at the time and new hires from members were able to bridge their service years, Sugg is credited with 35 years with the grid operator.

Her career has spanned every level of the RTO’s leadership, including roles as senior vice president of information technology and chief security officer.

Michael Deselle, SPP’s chief compliance and administrative officer, also has announced his retirement, effective at year-end. He joined the RTO in 2006 after 14 years at Central and South West and American Electric Power.

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Maryland Energy Administration, PSC Staff Clash on Future of Gas

Instead of continuing to build pipeline systems and replace aging pipes with expensive new ones that raise rates for customers, Maryland’s gas utilities should first look at non-pipes alternatives (NPAs) such as identifying and sealing leaky pipe joints, said Joyce Lombardi, energy policy manager at the Maryland Energy Administration.

“There’s a robot that can do this,” Lombardi told the Maryland Public Service Commission on July 31, during the continuation of its July 25 public hearing on the future of natural gas in the state. “It just zips underground. It goes into a working pipe, seals the joints; no one up top knows about it. [It] lasts for 50 years. It is one-third of the cost of traditional pipe replacement [and is] being used in New York and Rhode Island.”

The PSC heard two presentations with strongly opposing views at the July 31 hearing: one from the MEA and one from the commission’s own staff attorneys.

Lombardi focused on practical actions, which she said the PSC has the legal authority to take in the short term, such as requiring gas utilities to consider NPAs, while staff laid out complex and at times seemingly contradictory arguments on the fine points of existing legislation and whether any action on the future of gas is currently needed.

“The General Assembly should be given the opportunity to ratify or modify the commission’s decisions after the commission has had the opportunity to create a thorough review of the factual record,” said Staff Counsel Lloyd Spivak.

The hearings were triggered by a petition from the Office of People’s Counsel, filed in February 2023, asking the PSC to open a docket on the future of natural gas, and natural gas infrastructure and utilities, in the state. At the July 25 hearing, People’s Counsel David Lapp argued that Maryland’s ambitious climate targets and push for electrification of heating and cooling would decrease gas demand and the need for ongoing pipeline buildout and replacements. (See Maryland PSC Opens Debate on Future of Gas.)

Under the Climate Solutions Now Act (CSNA) of 2022, Maryland is committed to cutting its greenhouse gas emissions 60% by 2031, and Gov. Wes Moore (D) has pledged the state will have a 100% clean electric system by 2035.

The result, Lapp said on July 25, is that “there’s a massive disconnect between the technology, climate policy and what’s actually going on with the state’s gas utilities,” which have been spending hundreds of millions of dollars per year on pipeline replacement projects while increasing customer bills — in some cases, threefold.

Lapp stressed at the earlier hearing that OPC’s goal was not shutting down the state’s natural gas utilities, but rather to have the commission consider a “wide spectrum” of pathways for these companies to plan for substantially downsized demand and capital spending.

A panel of four PSC staff attorneys initially seemed to support the OPC petition, saying that a proceeding on the future of natural gas would be “necessary in order to achieve the goals laid out in the CSNA,” according to Harrison Scherr, who led off the presentation.

But Scherr and the other attorneys then qualified that support with a series of legal and technical considerations, finally recommending the commission take no immediate action beyond possibly launching a work group or several feasibility studies.

The PSC has “broad authority to regulate the gas utilities … [but] changes in commission policy should proceed with a rule making,” Scherr said. “It should be a very thorough path that we move forward. [Any] actions and policy decisions regarding the transition away from gas should be consistent with guidance from the General Assembly.”

Similarly, Scherr first said that the CSNA tasks the commission with determining how the law’s GHG reduction goals should be achieved, but then backtracked, saying, “It is the responsibility of the General Assembly to set the course by choosing a GHG reduction pathway and enacting enabling legislation.”

Spivak noted that natural gas — used as fuel, for electricity and from its own production facilities — accounts for about 19.5% of Maryland’s greenhouse gas emissions and contested the OPC’s figures on the increasing adoption of heat pumps across the state.

He discounted a 3.8% increase in electric heating customers from 2013 to 2022 — versus a .3% increase in natural gas customers — by speculating that “customers are switching from propane or oil to electric and are not necessarily switching from gas to electric.”

He argued for a balance of climate and public safety considerations in any review of Maryland’s natural gas policies, calling for feasibility studies to look at options like renewable natural gas or geothermal energy or whether the state has the workforce or enough heat pumps to support widespread electrification. A “human feasibility study” may also be needed to look at “the willingness of citizens to switch,” he said.

National Trends

The primary impetus for the OPC’s petition was a 2013 law called the Strategic Infrastructure Development and Enhancement (STRIDE) Act (S.B. 8/H.B. 89), which has allowed the gas utilities to recover the costs of certain pipeline replacements before they are completed, resulting in significant increases in gas utility bills.

But the OPC petition is also part of a larger national trend as other states look to curb emissions from natural gas and face pushback from the industry. As detailed in the petition’s appendices, the California Public Utilities Commission in 2022 passed a first-in-the-nation rule eliminating subsidies for natural gas hookups — still allowed in Maryland. It also passed a general order requiring gas utilities to get PUC approval for any projects costing more than $75 million and potentially causing significant environmental impacts.

Colorado, Massachusetts, Minnesota, New Jersey, New York, Rhode Island and the District of Columbia also have proceedings underway looking at how to balance their emission reduction goals with the public safety imperatives of existing natural gas systems. In 2021, for example, Minnesota passed the Natural Gas Innovation Act (NGIA), requiring the state’s natural gas utilities to develop plans for how they will use “innovative resources” to decarbonize their operations.

In 2022, the Minnesota Public Utilities Commission issued an order setting standards for energy efficiency and electrification investments that will comply with the NGIA.

While the PSC has yet to rule on the OPC’s petition, Chair Frederick H. Hoover did acknowledge the July public hearings as de facto proceedings on the future of natural gas. Other drivers for the PSC could be the executive order Gov. Moore signed in June, calling for the state to establish a zero-emission heating equipment standard and a new clean heat standard to be added to the state’s renewable portfolio standard.

Moore also signed a new law (H.B. 397) in May, requiring gas utilities to develop geothermal pilot projects to provide power to specific neighborhoods, also aimed at cutting back the need for natural gas pipelines. The utilities’ plans will go to the PSC for approval.

As these policies and programs come into effect, Lombardi stressed that requiring gas utilities to demonstrate that they are giving serious consideration to non-pipes alternatives should be a first step for the commission.

“This would be for all capital infrastructure spending, including capacity and line extensions to the extent possible,” she said. “Again, this is a floor, not a ceiling.”

In addition to pipe repairs, like joint resealing, Lombardi said definitions of NPAs should include both demand response and targeted electrification, a strategy for selectively swapping out natural gas for electric heating, or other electric appliances in locations that could most benefit from electrification.

“You can electrify just a few houses or an apartment building or an entire neighborhood maybe that has a high energy burden, or maybe a neighborhood that already has a lot of leaks,” she said.

That idea won support from Commissioner Bonnie Suchman, who said targeted electrification could be an effective, incremental approach to reducing both emissions and gas networks.

“The idea of targeted electrification is a much easier pill to swallow than sort of all-or-nothing,” she said. “And it gets us focused on what makes the most sense for an individual as opposed to just full-on electrification.”

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California Labor Groups Affirm Support for Pathways Proposal

Labor groups that blocked past California legislative efforts to “regionalize” CAISO told state lawmakers Aug. 6 they “look forward” to working with the legislature next year to pass a bill to implement the governance changes to the ISO being developed by the West-Wide Governance Pathways Initiative. 

The statement by the California Coalition of Utility Employees and the California State Association of Electrical Workers to a key State Senate committee might mark the unofficial start of the legislative campaign to allow CAISO to hand off oversight of its Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) to the Pathways Initiative’s proposed “regional organization” (RO). 

It also confirms that Pathways has the support of a key constituency needed to advance that change. 

“As you all know, we’ve been the proverbial fly in the ointment and opposed all three of the prior legislative attempts at regionalization,” Scott Wetch, a lobbyist representing the labor groups, told the Senate’s Energy, Utilities and Communications Committee during an oversight hearing on state agency efforts to maintain electric reliability in the face of extreme weather and the transition to emissions-free resources. 

“Those proposals would have transformed … CAISO itself into an RTO. In contrast, the Pathways Initiative would preserve … CAISO and its balancing authority and other functions, except for control over the energy markets,” Wetch said during a public comment period at the end of the hearing. 

Bills to convert CAISO into an RTO failed three years in a row over the 2016-2018 sessions, largely because of opposition from the International Brotherhood of Electrical Workers (IBEW), as well as resistance from publicly owned utilities in California and some environmental groups worried about the impact on the state’s renewable energy goals. 

Those bills would have extended the boundaries of the ISO’s balancing authority area to include states with utilities opting to join the expanded market. Under California law, that could have meant that the portion of projects that California’s renewable portfolio standard requires to be interconnected directly to the ISO’s BAA would be built outside the state, reducing job opportunities for IBEW members — a nonstarter for the union. 

“I also just want to emphasize that the Pathways proposal being developed would preserve California jobs, unlike previous regionalization proposals,” Wetch told senators. He also noted the plan “will enable many more utilities around the West to join” EDAM. 

“I want to emphasize that we foresee that the proposal would not affect California’s or any other state’s ability to protect its policies such as renewable portfolio standards, transmission planning, cost allocation or GHG reduction,” Wetch said. “It could even enhance our ability to decarbonize at lower cost by allowing us to use solar, wind and hydro resources more efficiently.” 

The change of heart among California labor groups became evident last year when Marc Joseph, an attorney for the IBEW, joined the Pathways Launch Committee. 

“Frankly, I wouldn’t be spending this much time [on Pathways] if I thought this was going to crash and burn,” Joseph said during an April meeting of that committee. (See Past Opponents Now See Legislative Pathway to CAISO Regionalization.) 

No Clear Road Map

During a Pathways workshop Aug. 5 to examine issues related to altering the CAISO tariff and migrating ISO functions to the RO, Launch Committee member Evie Kahl, general counsel for the California Community Choice Association, provided clarification on what a proposed bill would seek to achieve. 

“When we talk about the legislative change for any of this, what we’re looking at is not a legislative change to enable the CAISO to become a different entity than it is today, but to provide these [market] services and to allow California’s BA to participate in the RO market,” Kahl said, adding that the legislation will not determine what services the RO can offer. “That’s all independent.” 

Launch Committee members have made clear that the committee itself is prohibited from attempting to influence legislation because Pathways is a nonprofit 501(c)(3) organization, although some of its members could act in that capacity as representatives of their employers. 

Asked how specific the legislation would need to be to allow a scenario in which the RO takes on a larger portion of the ISO’s market functions and legal responsibilities (what Pathways is calling Option 2.5), compared with a more limited assumption of functions (Option 2.0), committee member Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said he hesitated to “get too far into the weeds” about legislation the group is not directly shaping. 

“I do think there is a pretty plausible legislative route that is permissive and does not get into the specifics of prescribing changes specific to 2.0 or 2.5. In other words, the legislation could look exactly the same,” Gray said. 

“What would be different, potentially in the legislative process, is more clarity from the Launch Committee and stakeholders in support of a particular outcome — 2.0 or 2.5 — that would inform the deliberations,” he said. “But the actual changes to California law don’t necessarily need to be different, and a more prescriptive approach may raise some issues on its own, as opposed to a more permissive approach.” 

The Aug. 5 workshop offered insight into the broad spectrum of issues and level of complexity that participants in the Pathways CAISO Issues and Tariff Analysis Work Group confront as they sort out the future relationship between the RO and ISO, including relative levels of independence, responsibility and liability for market issues, as well as what services each might provide over time. 

“We are really creating something new here,” Kahl said. “Everything that’s being outlined — there have been pieces of this developed across the country with different RTOs, but we’re putting the pieces together differently. In other words, there really hasn’t been a clear road map for us to do what we’ve been doing.” 

In his comments to the senators, Wetch expressed confidence in the outcome. 

“We are pleased with the progress that the [Pathways] Launch Committee has made in the past year. We remain optimistic that the Launch Committee will be able to make a recommendation to create a new regional organization and transfer oversight of the energy markets from the CAISO to the new regional organization,” he said. 

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CISA Launches Cybersecurity Software Buying Guide

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released a guide to help organizations determine their software suppliers’ approach to cybersecurity in order to prevent nonsecure code from getting into their systems. 

CISA’s Secure by Demand Guide, published Aug. 6, provides “questions and resources” that software buyers can use to double-check their suppliers. The agency said that while staff in charge of software acquisition at an organization usually understand the core cybersecurity requirements for a desired technology, they often do not check whether suppliers have “practices and policies in place to ensure that security is a core consideration” at all stages of development. 

The document is intended as a complement to the agency’s Secure by Design Guide, released a week earlier. That guide aims to help instill in software developers the philosophy of building cybersecurity into their products from the ground up and taking proactive steps to ensure their software is free of vulnerabilities. A secure-by-design approach follows three principles: 

    • Take ownership of customer security outcomes. 
    • Embrace radical transparency and accountability. 
    • Build organizational structure and leadership to achieve these goals. 

With the new guide, CISA said, businesses can make sure suppliers are following these principles. 

“We are glad to see leading technology vendors recognize that their products need to be more secure. … Businesses can also help move the needle by making better risk-informed decisions when purchasing software,” CISA Director Jen Easterly said in a statement. “This new guide will help software customers understand how they can use their purchasing power to procure secure products and turn secure by design into secure by demand.” 

In the guide, CISA said businesses’ due diligence of software manufacturers “often [focuses] on [the manufacturers’] enterprise security measures,” which they examine through the lens of compliance standards. However, this focus on enterprise security — which relates to how the company protects its own infrastructure — can come at the expense of neglecting the vendor’s product security, by which the company ensures its products are safe from attacks. 

The guide urged organizations to look for ways to make product security a focus at each stage of procurement. Before procurement, an organization can use probing questions to evaluate a manufacturer’s understanding of product security; during procurement, the organization can write product security requirements into its contract language; and afterward, it can continue to assess the product security and security outcomes. 

Suggested general questions for software manufacturers include whether the manufacturer has taken CISA’s Secure by Design Pledge, how it measures its adherence to the pledge, and to what extent it supports security patches. Additional questions cover a number of specific topics: 

    • authentication — whether the product supports secure authentication measures such as single sign-on and multifactor authentication and has eliminated default passwords in its products. 
    • eliminating classes of vulnerability — what vulnerability classes the manufacturer has addressed systematically in its products, and whether it has a road map for eliminating those classes. 
    • evidence of intrusions — whether manufacturers make security logs available to customers in the baseline version of their products. 
    • software supply chain security — whether the manufacturer generates a software bill of materials in a standardized format that is available to customers, and how it vets the security of open source software components. 
    • vulnerability disclosure and reporting — whether the manufacturer demonstrates transparency and timeliness in vulnerability reporting for its products. 

Describing the guide as “a starting point for software customers to generate the demand for more secure technology products,” CISA advised businesses to use additional resources, such as its Software Acquisition Guide for Government Enterprise Consumers and the National Institute of Standards and Technology’s Secure Software Development Framework.